Means of Affecting Separation

ABSTRACT

Herein is provided processes for affecting the separation of oil from emulsions by the addition of nanogas solutions. For example, the nanogas solutions can be used to affect the viscosity and/or density of oil droplets in oil-in-water emulsions, break the oil-in-water emulsion; and form an oil phase floating on a water phase. In another example, the nanogas solutions can be used in conjunction with a floatation tank to separate oil from, for example, produced water. In other examples selection of the gasses in the nanogas solution can be used to affect reactions and/or separation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This disclosure claims the benefit of priority to U.S. Appl. No.62/337,431, filed 17 May, 2016, the disclosure of which is incorporatedherein in its entirety.

FIELD OF THE INVENTION

This disclosure is directed to methods of affecting the viscosities ofoils for the separation of these oils from emulsions.

BACKGROUND

Subsurface geological operations such as mineral mining, oil welldrilling, natural gas exploration, and induced hydraulic fracturinggenerate wastewater contaminated with significant concentrations ofimpurities. These impurities vary widely in both type and amountdepending on the type of geological operation, the nature of thesubsurface environment, and the type and amount of soluble mineralspresent in the native water source. The contaminated water is eventuallydischarged into surface waters or sub-surface aquifers. In some cases,wastewater generated from drilling and mining operations have resultedin making regional water supplies unusable. Induced hydraulic fracturingin particular is a highly water-intensive process, employing waterpumped at pressures exceeding 3,000 psi and flow rates exceeding 85gallons per minute to create fractures in subsurface rock layers. Thesecreated fractures intersect with natural fractures, thereby creating anetwork of flow channels to a well bore. These flow channels allow therelease of petroleum and natural gas products for extraction. The flowchannels also allow the injected water plus additional native water toflow to the surface along with the fuel products once the fractures arecreated.

Flowback water, and produced water, from subsurface geologicaloperations contains a variety of contaminants. Often, produced water is“hard” or brackish and further includes dissolved or dispersed organicand inorganic materials. Produced water can include chemicals used inthe mining operation, such as hydrocarbons that are injected along withwater to facilitate fracture formation in hydrofracturing. One commontype of contaminant present in produced water from hydrofracturing is amixture of free and emulsified oil together with gel-like accumulationsof hydrocarbons. In most cases, this oily mixture further contains silt,sand, and/or clay particulates gathered by the produced water as ittravels to the surface. These oily mixtures are neutrally buoyant—thatis, they neither sink nor float, or they require extended times to sinkor float—in produced water. While in some cases these oily mixtures arevisible as agglomerated, black, and tarry-looking residues, in othercases the oily mixtures, or some portion thereof, are finely divideddispersed liquids or liquid/solid droplets or particles presentthroughout the water phase.

Conventional oil separation processes relying on density differences areincapable of effectively separating this oily mixture from producedwater. Conventional filtering methods employ screen or filter media thatare quickly clogged by the oily mixture. Gravity separation is not onlyslow but also requires the use of large tanks and low flow rates inorder to provide the long residence times needed to achieve an effectiveseparation. Even with very long residence times, very well dispersed,fine oily mixture droplets are sometimes inseparable from the waterphase. Methods such as evaporation of water from the mixture are notonly time intensive, but highly energy intensive as well, andimpractical for mining operations where large volumes of produced waterare generated in short periods of time. Thus, current processes forremoving such material suffer many drawbacks.

Further remediation of produced water is only possible once this oilymixture is removed. Therefore, there is a need for a process foreffectively removing neutrally buoyant materials from water. Forexample, in the mining industry, there is a need for a process toeffectively remove an oily mixture from produced water in an efficientmanner to result in produced water that is substantially free ofemulsified petroleum, sand, silt, clay, and gel-like hydrocarbons. Thereis a need to remove neutrally buoyant materials other than such oilymixtures from water. There is a need for these processes to operatewithout undue energy expenditure. There is a need for these processes tooperate at a rate that is commensurate with water-intensive applicationssuch as hydrofracturing.

SUMMARY

One embodiment is a process that includes admixing a nanogas solutionand an oil-in-water emulsion; breaking the oil-in-water emulsion; andforming an oil phase floating on a water phase; wherein the nanogassolution is a homogeneous mixture of nanobubbles and water.

Another embodiment is a process that includes providing a floatationtank having an inlet end and an outlet end; the floatation tankincluding an oil-in-water emulsion inlet and a first nanogas inletproximal to the inlet end, and having an underflow baffle proximal tothe outlet end; providing an oil-in-water emulsion to the floatationtank via the oil-in-water emulsion inlet; providing a nanogas solutionto the floatation tank via the first nanogas inlet thereby admixing thenanogas solution with the oil-in-water emulsion; breaking theoil-in-water emulsion and forming an oil phase floating on a waterphase; separating the water phase from the oil phase by carrying thewater phase under the underflow baffle.

Still Another embodiment is a process that includes admixing a nanogassolution an oil sand tailings; breaking the oil sands tailings into anoil phase, a water phase, and a solids phase; and separating the phases.

Yet another embodiment is a process that includes shearing a firstnanogas solution into an oil-in-water micro emulsion; breaking theoil-in-water micro emulsion and forming a water-in-oil macro emulsion, awater phase, and a solids phase, where the water-in-oil macro emulsionis carried on the water phase; and collecting oil from the water-in-oilmacro emulsion; wherein the nanogas solution consists essentially of ahomogeneous mixture of nanobubbles and water.

Yet still another embodiment is a process that includes providing afloatation tank having an inlet end and an outlet end; the floatationtank including an oil-in-water emulsion inlet and a first nanogas inlet,both, proximal to the inlet end, and having an underflow baffle proximalto the outlet end; providing an oil-in-water emulsion to the floatationtank via the oil-in-water emulsion inlet; providing a nanogas solutionto the floatation tank via the first nanogas inlet thereby admixing thenanogas solution with the oil-in-water emulsion without the formation ofmacrobubbles; breaking the oil-in-water emulsion and forming an oilphase floating on a water phase; and separating the water phase from theoil phase by carrying the water phase under the underflow baffle.

Still yet another embodiment is a method that includes admixing ananogas solution with oil sands tailings; and separating materialsincluding silts, residual bitumen, and organic compounds from water inthe oil sands tailings; wherein the nanogas solution is anitrogen-nanogas solution or an ON-nanogas solution.

Another embodiment is a method that includes admixing an oxygen-nanogassolution or an ON-nanogas solution with an aqueous solution thatincludes hydrogen sulfide; and oxidizing the hydrogen sulfide.

Yet another embodiment is a method that includes admixing anoxygen-nanogas solution or an ON-nanogas solution with a slurry of ironsulfide and water; and oxidizing the iron sulfide to iron oxide.

BRIEF DESCRIPTION OF THE FIGURES

For a more complete understanding of the disclosure, reference should bemade to the following detailed description and accompanying drawingfigures wherein:

FIG. 1 is a process diagram of a process described herein; and

FIG. 2 is a cross section of a separation tank showing the inflow andoutflow of agents.

While specific embodiments are illustrated in the figures, with theunderstanding that the disclosure is intended to be illustrative, theseembodiments are not intended to limit the invention described andillustrated herein.

DETAILED DESCRIPTION

A first embodiment is a process of breaking an oil-in-water emulsion. Asused throughout, emulsions are oil-in-water emulsions. The process caninclude admixing a nanogas solution and an emulsion; breaking theemulsion; and forming an oil phase floating on a water phase.Preferably, the emulsion can be flow back water, produced water, or oilsands tailing water. In other examples, the emulsion can be mayonnaise,butter, or a palm oil-in-water emulsion.

Notably, the nanogas solution is a homogeneous mixture of nanobubblesand water. As used herein, the term “nanobubbles” means bubbles of a gaswithin a liquid, wherein the bubbles having an average diameter of about10 nm to 100 nm; preferably, wherein there are no bubble having adiameter of greater than about 500 nm, about 400 nm, about 300 nm, about250 nm, or about 200 nm, more preferably, there are no microbubbles. Theherein utilized nanobubbles can be formed in or by a nanogas solutiongenerator, one example of which is provided in U.S. Pat. No. 9,586,186which is incorporated herein in its entirety. Additional means forforming the herein utilized nanobubbles include those machines andmethods described in U.S. Pat. No. 8,500,104.

The nanogas solution is preferably homogeneous, that is, the nanobubblesare evenly distributed throughout the solution and appear as a suspended“particulate” in the liquid. Notably, the liquid may further besaturated with or near saturation with the gas that comprises thenanobubbles. A mixture of bubbles and liquid wherein the bubblescoalesce and/or rise to the surface and break is not a homogeneousmixture of nanobubbles and the liquid.

The homogeneous mixture can include nanobubbles that include, consistessentially of, or consist of oxygen (O₂), nitrogen (N₂), carbon dioxide(CO₂), or a mixture thereof; and can include a liquid that is water, forexample, distilled water, di-water, ground water, municipal water,collected water, or recycled water. As used herein, the terms oxygen andnitrogen refer to the gasses O₂ and N₂ whether or not the term oxygengas or nitrogen gas is used.

In one instance, the homogeneous mixture includes collected water; asused herein collected water means the water that has been used in theoil industry for the hydraulic fracturing of subterranean formations,well stimulation or treatment, specifically water that has beencollected from a subterranean use. In another instance, the homogeneousmixture includes recycled water, as used herein recycled water means thewater has been passed through the herein disclosed process of breakingan emulsion. FIG. 1 shows a schematic of a general process of breakingthe emulsion. Notably, the dashed lines denote the optional use of thewater separated from the emulsion as the feed water or generator waterfor the nanogas solution (feeding into a nanogas solution generator).

In yet another instance the homogeneous mixture (i.e., the nanogassolution) includes oxygen, nitrogen, carbon dioxide, or a mixturethereof. In one example, the nanogas solution is a nitrogen-nanogassolution wherein the solution includes, consists essentially of, orconsists of nitrogen (N₂) and the water. Herein, the term consistsessentially of refers to the inclusion of salts, gases, or solutes thatmay occur in the water (liquid) but have no effect on the performance ofthe nanogas solution in the herein disclosed processes. Notably, unlessrigorously cleaned and degassed, water will always include someconcentration of contaminants (solutes and gases). Furthermore, the termconsisting essentially of includes the use of recycled water for theformation of the nanogas solution; in this instance, the solution willconsist of the gas, water (H₂O), and minor concentrations of compoundsfound in the emulsion from which the recycled water was obtained.Herewith, the nanogas solution preferably consists essentially of thegas and water, wherein the contaminants in the water do not affect theperformance of the solution. In another example, the nanogas solution isan oxygen-nanogas solution wherein the solution includes, consistsessentially of, or consists of oxygen and water. In still anotherexample, the nanogas solution is a ON-nanogas solution wherein thesolution includes, consists essentially of, or consists of oxygen,nitrogen, and water. Herein, an ON-nanogas includes molar ratios ofoxygen to nitrogen of 99:1 to 1:99, for example 99:1, 90:1, 80:1, 70:1,60:1, 50:1, 40:1, 30:1, 20:1, 10:1, 1:1, 1:10, 1:20, 1:30, 1:40, 1:50,1:60, 1:70, 1:80, 1:90, and 1:99. Preferred molar ratios include about18:82, 21:79, 28:72, 30:70, 32:68, 35:65, 40:60, 42:58, and 50:50. Otherparticularly relevant molar ratios can be selected from 50:50; 60:40;70:30; and 80:20. In yet still another example, the nanogas solutionincludes carbon dioxide wherein the solution includes, consistsessentially of, or consists of carbon dioxide and water, more preferablya mixture of carbon dioxide, nitrogen, and water.

In one example, the process includes admixing a nitrogen-nanogassolution with the emulsion. Preferably, the process includes breakingthe emulsion and forming (and separating) a water phase and anitrogen-oil phase. Herein, the term nitrogen-oil phase is a designationof source for the material coming from the treatment of the emulsionwith the nanogas solution. In some examples, the nitrogen-oil phaseincludes nitrogen gas. In one example, the emulsion is an emulsion of acrude oil and water (e.g., a produced water, flow back water, or oilsands tailing water) and, from the admixing of this emulsion with thenitrogen nanogas solution is, preferably, separated a light crude oil (acrude oil having a API gravity of higher than 31.1°). More preferably,the emulsion is an emulsion of heavy (API gravity of less than 22.3°)and/or medium (22.3° to 31.1°) crude oil in water and the processprovides a water phase and a nitrogen-oil phase. The nitrogen-oil phasecan be a light oil phase, a medium oil phase, or a heavy oil phase;notably, the nitrogen-oil phase is preferably an admixture of water,oil, and gas that floats on the water phase. In specific examples, thenitrogen-oil can be separated from the water phase (for example, byoverflow of a separation weir). The water retained in the nitrogen oilphase can then be removed (e.g., by cyclone separation, emulsionbreaking, or absorption) leaving the oil phase. The isolated oil phasecan be a heavy or medium oil. That is, the admixing of thenitrogen-nanogas solution with the emulsion, breaks the emulsion andcarries a nanogas-oil phase on a water phase, the nanogas-oil phase canbe separated and dried to leave a heavy oil. Unexpectedly, thenitrogen-oil phase has been separated and dried of residual water,leaving an oil having an API gravity of about 8-10. That is, the processcan separate carry and separate very heavy oil from produced water oroil sands tailings.

In one example, the nitrogen-nanogas solution can include, consistessentially of, consist of nanobubbles that include at least 80%, 90%,or 95% nitrogen and water. Preferably, the nitrogen-nanogas solutionconsists of nitrogen nanobubbles and water wherein the nitrogennanobubbles include at least 90%, or at least 95% nitrogen gas. Theprocess, preferably, further includes separating an underlying waterphase and the nitrogen-oil phase (which floats on the water phase). Theunderlying water phase can be recycled for the preparation of a nanogassolution; the nitrogen-oil phase is, preferably, recovered and can beprocessed (e.g., pumped to storage facilities).

The process can further include separating a precipitate or solid fromthe water phase. In one example, the addition of the nitrogen-nanogassolution to the emulsion provides a tri-phase or three component mixtureof a nitrogen-oil phase, a water phase, and a precipitate. For example,emulsion can include bitumen, iron sulfide, shale, sand, and/or othersubterranean component (herein subterranean components means materialsother than water and oil that are carried to the surface duringhydrocarbon extraction). In this example, the subterranean component(including bitumen, iron sulfide, shale, sand, and other materials) isthe precipitate. That is, the process can break both the emulsion(separating oil and water) but can contemporaneously separate solidsubterranean components from the oil droplet.

In another example, the process includes admixing an oxygen-nanogassolution with the emulsion providing an oxygen-oil phase. Preferably,the oxygen-nanogas solution includes oxygen nanobubbles composed of atleast 80%, 90%, or 95% oxygen. Preferably, the nanogas solution consistsessentially of, more preferably consists of oxygen nanobubbles and waterwherein the oxygen nanobubbles includes at least 90%, or at least 95%oxygen. Preferably, the process includes breaking the emulsion andforming (and separating) a water phase and an oxygen-oil phase. Herein,the term oxygen-oil phase is a designation of source for the materialcoming from the treatment of the emulsion with the nanogas solution, insome examples the oxygen-oil phase includes oxygen gas (O₂). In oneexample, the emulsion is an emulsion of a crude oil and water (e.g., aproduced water, flow back water, or oil sands tailing water) and, fromthe admixing of this emulsion with the oxygen nanogas solution is,preferably, separated a crude oil. As distinct from the addition of thenitrogen-nanogas solution as described above, the addition of theoxygen-nanogas solution to the emulsion provides the separation of amedium or heavy crude oil. Even more typically, the addition of theoxygen-nanogas solution provides the separation of an agglomerated oilmixture (which can include water) that does not freely flow but canfloat on water.

In one example, the oxygen-nanogas solution can include, consistessentially of, consist of nanobubbles that include at least 80%, 90%,or 95% oxygen and water. Preferably, the oxygen-nanogas solutionconsists of oxygen nanobubbles and water wherein the oxygen nanobubblesinclude at least 90%, or at least 95% oxygen gas. The process,preferably, further includes separating an underlying water phase andthe oxygen-oil phase (which floats on the water phase). The underlyingwater phase can be recycled for the preparation of a nanogas solution;the oxygen-oil phase is, preferably, recovered and can be processed(e.g., pumped to storage facilities).

In another preferable instance, the process includes reducing aconcentration of hydrogen sulfide in the emulsion or in a separatedwater phase. Preferably wherein the hydrogen sulfide concentration isreduced to a level below about 10 ppm, 5 ppm, or 1 ppm. The reduction ofthe hydrogen sulfide concentration can include the formation of sulfiteand sulfate species in the water. In one example, the addition of theoxygen-nanogas solution to the emulsion or the separated water providesa sufficient concentration of oxygen that the hydrogen sulfide isoxidized. In another example, the addition of the oxygen-nanogassolution to a mixture of hydrogen sulfide and water oxidizes the sulfideto a sulfite and/or sulfate. Preferably, the sulfide (S²⁻) is oxidizedto sulfite (SO₃ ²⁻) and/or sulfate (SO₄ ²⁻) in water (e.g., the H₂S orX(SH) oxidized to hydrogen sulfite, hydrogen sulfate, or the saltsthereof). In certain examples, the emulsion (or the water solution)includes ions or agents that react with and/or bind the sulfite orsulfate and precipitate this sulfur species from the solution.

In yet another preferable instance, the process can include reducing aconcentration of iron in the emulsion; affecting the separation of ironfrom water; and/or oxidizing iron sulfide (e.g., FeS), for example, toreduce any likelihood pyrophoric actions upon removal. Notably, flowback water, produced water, or oil sands tailing water can include aconcentration of iron sulfide, typically FeS. In one example, themajority (preferably all) of the iron sulfide can be separated from anemulsion by the addition of a nitrogen nanogas solution; this processbreaks the emulsion and precipitates the iron sulfide. In someinstances, portions of the iron sulfide may stay suspended in the waterphase; in these instances, the addition of an oxygen nanogas solutionprovides an admixture that can be filtered without irreversibly cloggingfilter membranes or screens. In another example, the iron sulfideconcentration in the water phase is reduced to a level below about 10ppm, 5 ppm, or 1 ppm. Preferably, the addition of the oxygen nanogassolution provides an admixture that can be filtered and the filterscreen back washed. Notably, the iron sulfide suspended in the solutionwithout the addition of the oxygen-nanogas solution is an admixturecapable of filtration but clogs the screens and cannot be backwashed. Inone example, the addition of an oxygen-nanogas solution or an ON-nanogassolution to an admixture of iron sulfide and water (obtained from anemulsion) partially oxidizes the surface of the iron sulfide, decreasesthe adhesion of oil to the surface of this oxidized material, andpermits for the more facile filtration. In another example, the ironsulfide can be oxidized to iron oxide (Fe₂O₃ or FeO). Herein, anoxygen-nanogas solution can be added to an admixture of water and ironsulfide; in one example the admixture of water and iron sulfide isselected from the emulsion (unseparated), a separated water phase thatincludes iron sulfide, or a slurry of iron sulfide and water (forexample, a slurry that was previously separated from the emulsion by theaddition of a nitrogen-nanogas solution; or a slurry that is theresuspension of separated iron sulfide, and optionally other materials,in water)). Preferably, the iron sulfide is quantitatively converted toan iron oxide.

In still another instance, the process can include admixing anON-nanogas solution with the emulsion. In this instance, the additioncan afford the reduction of the sulfide concentration in the separatedwater, the reduction of the iron sulfide concentration in the separatedwater, a lightening of the separated oil phase, and or a mixturethereof. In one example, the nanogas solution is a ON-nanogas solutionwherein the solution includes, consists essentially of, or consists ofoxygen (O₂), nitrogen (N₂), and water. Herein, an ON-nanogas includesmolar ratios of oxygen to nitrogen in the range of 99:1 to 1:99;examples include 99:1, 90:1, 80:1, 70:1, 60:1, 50:1, 40:1, 30:1, 20:1,10:1, 1:1, 1:10, 1:20, 1:30, 1:40, 1:50, 1:60, 1:70, 1:80, 1:90, and1:99. Preferred molar ratios include about 18:82, 21:79, 28:72, 30:70,32:68, 35:65, 40:60, 42:58, and 50:50. One particularly relevant molarratio is 21:79 (air). Other particularly relevant molar ratios can beselected from 50:50; 60:40; 70:30; and 80:20. In particular, the amountof oxygen (relative to the amount of nitrogen) can be varied to achievedifferent results (oxidation vs separation), and the higher theconcentration of the composition that is desired to be oxidized (e.g., asulfide) the higher the oxygen concentration can be.

In yet another instance, the process can include admixing the emulsionwith a first nanogas solution. The process can then include either (A)separating the admixture into components (i.e., oil phase, water phase,and possibly solid phase) and then admixing the water phase with asecond nanogas solution, or (B) prior to separating the components,adding a second nanogas solution to the first admixture. When the firstadmixture is a heterogeneous admixture (having at least an oil phase anda water phase), the second nanogas solution is preferably added to thewater phase. In one example, the first nanogas solution is anitrogen-nanogas solution and the second nanogas solution is an oxygennanogas solution. In a second example, the first nanogas solution is anoxygen nanogas solution or an ON-nanogas solution and the second nanogassolution is a nitrogen-nanogas solution. In a third example the firstnanogas solution is selected from the group consisting of a nitrogen-,an oxygen-, and a ON-nanogas solution; and the second nanogas has acomposition that is different from the first nanogas solution and isselected from the group consisting of a nitrogen-, an oxygen-, and a ON—nanogas solution.

Preferably, the addition of the nitrogen-nanogas to the water phaseforms a nitrogen-oil phase which has a viscosity that is lower than aviscosity of the oxygen-oil phase. That is, the addition of thenitrogen-nanogas solution (e.g., to the broken emulsion formed by theadmixing of the oxygen-nanogas solution and an emulsion) affects achange in the oil-phase carried on the water, thereby reducing theviscosity of the oil-phase and preferably furthering a separation of theoil and water. In one instance, this can be understood as a furtherlightening of the oil. In another instance, the addition of thenitrogen-nanogas solution affects a separation of the oil and anysubterranean components (e.g., solids). In one unexpected instance, theaddition of the oxygen-nanogas solution did not affect or affected to aminor extent the separation of the subterranean components and theaddition of the nitrogen-nanogas solution afforded separation orenhanced separation (beyond what is achievable with just the oxygennanogas solution). Still further, the nitrogen-oil phase is, preferably,separated from the underlying water phase and the oil is recovered andcan be processed.

Another example of the process described herein includes shearing afirst nanogas solution into an oil-in-water micro emulsion, and breakingthe oil-in-water micro emulsion and forming a water-in-oil macroemulsion, a water phase, and a solids phase, where the water-in-oilmacro emulsion is carried on the water phase. The process can alsoinclude collecting oil from the water-in-oil macro emulsion. Here, thenanogas solution consists essentially of a homogeneous mixture ofnanobubbles and water.

In one instance, shearing means contacting the nanogas solution and theoil-in-water micro emulsion in such a way that the oil droplets in theemulsion are disrupted, in one case made even smaller. In anotherinstance, shearing means injecting the nanogas solution between a doublelayer boundary of the oil droplets in the micro emulsion. The shearingcan involve providing a flow of the oil-in-water micro emulsion andinjecting a stream of the first nanogas solution into the micro emulsionflow at a direction that is 90° to 180° from the flow, preferably 115°to 180°, more preferably 135° to 180°. Preferably, the nanogas solutionis injected as a stream with sufficient pressure to provide turbulenceand shear in the micro emulsion flow. In one preferable instance, aplurality of nanogas solution streams are injected into the microemulsion flow path at angles ranging from 115° to 180° using a nozzle ortube. Preferably, the nozzle or tube does not constrict at itstermination as this constriction can disrupt the nanogas solution andpromote macrobubble formation. In another preferable instance, theplurality of nanogas solution streams intersect in the micro emulsionflow path. In another instance, the nanogas solution and the microemulsion can be intermixed in a volume (“mixer”) that can carry bothmaterials. Examples of a mixer can include a pipe carrying the microemulsion or can include shearing mixers or mixing containers (e.g.,rotostator mixers). This sheared admixture is then preferably ejected(transferred) into a separation container (e.g., a floatation tank, adrum, a pond).

The process can also include separating the water phase from thewater-in-oil macro emulsion and the solids. Notably, the separated waterphase can include nanobubbles; that is, the concentration of nanobubblesin the sheared admixture is sufficiently high that the nanobubbles arenot consumed or absorbed into the water-in-oil emulsion. This separatedwater, if containing a sufficient concentration of nanobubble can beused as a nanogas solution (e.g., sheared into an oil-in-water emulsionto provide the benefits described herein). Preferably, a portion of theseparated water is recycled and used to provide the first nanogassolution (e.g., by addition to a machine or process for the manufactureof a nanogas solution).

In another instance, the oil-in-water micro emulsion can include anumber of emulsifiers that promote or stabilize the emulsion. Notably,when the emulsion is the result of, for example, the petroleum industry,the micro emulsion can include emulsifiers selected from solids,asphaltenes, paraffins, resins, and mixtures thereof. Typically, theseemulsifiers are distributed at the interface between the oil dropletsand the water, stabilizing the oil droplets, preventing them fromagglomerating, and thereby stabilizing the emulsion. Notably, theseemulsifiers increase the zeta-potential of the oil droplets to preventthe agglomeration and separation of the oil. In one case, where thefirst nanogas solution is an oxygen-nanogas solution; the processinvolves absorbing oxygen nanobubbles into the emulsifiers, reducing thezeta potential of an oil droplet, and forming an admixture that includesa coagulum. Herein, the coagulum is an oil-in-water macro emulsion; thatis, the oxygen nanobubbles act as a chemical coagulant without theaddition of traditional coagulants. In this case, the macro-emulsion mayfloat or separate from the water but generally includes a highproportion of water to oil. Accordingly, the process preferably alsoincludes admixing a second nanogas solution with the admixture thatincludes the coagulum. Here, this second nanogas solution is anitrogen-nanogas solution which dissociates the emulsifiers from asurface of oil droplets in the oil-in-water macro emulsion, breaks theoil-in-water emulsion, and forms the water-in-oil macro emulsion.

Notably, the addition of a nitrogen-nanogas solution in the currentprocess has been found to support a process that includes dissociatingthe emulsifiers from a surface of oil droplets in the oil-in-water macroemulsion; breaking the oil-in-water emulsion; and forming thewater-in-oil macro emulsion. In one case, the nitrogen nanobubblesdisrupt the emulsifiers from the oil droplets and allow the oil todemulsify (e.g., group into larger drops). Notably, the addition of thenitrogen-nanogas solution in the current process separates a largepercentage (e.g., greater than 50 wt. %) of solids from the oil dropletscausing these solids to precipitate or settle from the solutions.

In one preferable case, the first nanogas solution can include carbondioxide and nitrogen; that is, nanobubbles of carbon dioxide andnitrogen (either as admixtures or separate nanobubbles). This case caninclude the absorption of the carbon dioxide (from the nanobubbles) intooil droplets (e.g., providing an oil-carbon dioxide composition).Preferably, the oil-carbon dioxide composition (carbon dioxide absorbedoil droplet) has a density that is less than the density of the oildroplet without the carbon dioxide. In this case, the separation of thecomponents of the emulsion can provide an water-in-oil macro emulsionwhich includes carbon dioxide in the oil.

In another case, the oil-in-water micro emulsion might include aconcentration of sulfides greater than 50 ppm, the sulfides selectedfrom iron sulfide, hydrogen sulfide, and a mixture thereof. This processcan include either (a) the first nanogas solution includes a sufficientquantity of oxygen nanobubbles to react completely with theconcentration of sulfides in the oil-in-water emulsion, thereby reducingthe sulfide concentration to less than 10 ppm, or (b) the processfurther includes admixing a second nanogas solution with the waterphase, wherein the sulfides of the oil-in-water micro emulsion arecarried into the water phase, and where the second nanogas solutionincludes a sufficient quantity of oxygen nanobubbles to react completelywith the concentration of sulfides in the water phase, thereby reducinga sulfide concentration to less than 10 ppm.

Notably, the embodiments provided herein proceed without the formationof macrobubbles. In one case, the first nanogas solution does not formmacrobubbles. Preferably, none of the nanogas solutions utilized hereinform or include macrobubble (i.e., any bubble larger than a nanobubble).Preferably, the water-in-oil macro emulsion (separated from the microemulsion) further does not include macrobubbles. In one instance, thewater-in-oil macro emulsion includes greater than about 50 wt. % oil,less than about 50 wt. % water, and further includes nanobubbles.

In another embodiment, the process of breaking the emulsion can beutilized to continuously or batch wise separate oil from water. Forexample, the process can be used to separate oil from water in oil fieldproduced water, collected water, or catch basins. More preferably, theprocess can be used to reduce the hydrocarbon content of a water andfacilitate reuse or disposal. In one instance (e.g., as shown in FIG. 2)the process can utilize a floatation tank 100 for the oil and waterseparation. The floatation tank 100 can have an inlet end 101 and anoutlet end 102; an emulsion inlet 103 and a first nanogas inlet 104proximal to the inlet end 101 and an underflow baffle 105 proximal tothe outlet end 102. Examples of floatation tanks include DAF tanks andAPI tanks. Preferably, the floatation tank is a circular or rectangularDAF tank; more preferably the floatation tank is a rectangular tank thatprovides at least 5 minutes, 10 minutes, 15 minutes, or 20 minutes ofresidency time in the tank.

The process can include providing an emulsion to the floatation tank 100via the emulsion inlet 103. The emulsion can be a produced water orcollected water from a well operation. The process can additionallyinclude providing a nanogas solution to the floatation tank via thefirst nanogas inlet 104. The process further includes admixing thenanogas solution with the emulsion. The admixing can be facilitated bythe hydraulic flow within the floatation tank or can be furtherfacilitated by the operation of a mixer (e.g., a paddle or propeller)within the floatation tank.

The process preferably includes breaking the emulsion and forming an oilphase 106 floating on a water phase 107. Herein, breaking the emulsionincludes the coalescence of the oil “droplets” to form an oil phase(e.g., an water-in-oil emulsion) carried by the water phase.

The process can then include separating the water phase from the oilphase. Preferably, the water phase is separated by carrying the waterphase 107 under the underflow baffle 105. In this instance, the oilphase is retained on the surface of the water phase. The oil phase canfurther be removed by an overflow or oil skimmer that can conduct theoil phase to a collection or storage apparatus.

In another instance, the floating tank 100 can include a second nanogasinlet 108 down steam from the first nanogas inlet and upstream from theunderflow baffle. Herein, downstream means a position closer to theoutlet end than the first nanogas inlet. Preferably, the second nanogasinlet is upstream of a midpoint between the inlet end and the outletend. Still more preferably, the second nanogas inlet is upstream of thefirst quarter point between the inlet end and the outlet end. In thisinstance, the process can further include providing a second nanogassolution to the floatation tank via the second nanogas inlet. Thereby,the second nanogas solution is preferably admixed with the water phasecarrying the oil phase, that is, the second nanogas solution is added tothe floatation tank at a position or time after the emulsion breaks.Preferably, the second nanogas solution is a homogeneous mixture ofnitrogen nanobubbles Yet another embodiment is a method of treatingtailing water from oil sands production processes. The method caninclude admixing a nanogas solution and oil sands tailings; and thenseparating materials including silts, residual bitumen, and organiccompounds from water in the oil sands tailings. As described above, thenanogas solution is a homogeneous mixture of nanobubbles and water. Inone instance, the nanogas solution is a nitrogen-nanogas solution and,preferably, the nitrogen-nanogas solution affects the viscosity ofmaterials in the oil sands tailings. In another instance, the nanogassolution is an oxygen-nanogas solution and, preferably, oxidizesvolatile materials in the oil sands tailings. In still another instance,the method includes admixing a second nanogas solution with theadmixture of the nanogas solution and the oil sands tailings; whereinthe nanogas solution is an oxygen-nanogas solution and the secondnanogas solution is a nitrogen-nanogas solution.

In one example, a nanogas solution is directly added to the tailings,preferably directly added to a tailings pond. For example, the nanogassolution can be injected or added to the tailing by subsurfaceinjection, that is, injection of the nanogas solution into the tailingsbelow the surface of the tailings pond. Recognizing the enormity oftailings ponds (e.g., those associated with tar sands recovery) thenanogas solution can be poured, sprayed, or distributed over the pond.In another example, the nanogas solution is added to the tailings priorto the addition of the tailings to the ponds; that is, at the end of thehydrocarbon recovery process. Preferably, the nanogas solution is mixedwith the tailings prior to addition of the tailings to the tailingspond. In yet another example, the nanogas solution can be mixed withtailings by pumping tailings from the tailings pond, admixing with thenanogas solution, and then returning the mixture to the tailings pond.

In a preferable example, the addition of the nanogas solution (e.g., anitrogen-nanogas solution) to the tailings pond increases the rate ofseparation of the oils, water, and solids contained in the tailings. Inanother preferable example, the addition of a nanogas solution thatincludes oxygen (e.g., an oxygen-nanogas solution or an ON-nanogassolution) and oxidizes hydrogen sulfide and/or other oxidizablecomponents of the tailings solution. In one example, the addition of anoxygen including nanogas solution additionally causes hydrocarbonmaterials to agglomerate and increase separation; in another example,the addition of a nitrogen nanogas solution separates and lightens theoil(s) and allows for more facile removal of the hydrocarbons from thesurface of the tailings pond. Preferably, the addition of the nanogassolution increases the settling rate by a factor of 1.1, 1.2, 1.3, 1.4,1.5, 1.6, 1.7, 1.8, 1.9, or 2.0. More preferably, the addition of thenanogas solution increases the settling rate by at least 2 times.

In a particular instance, the method can include admixing a nanogassolution with oil sands tailings and then separating materials includingsilts, residual bitumen, and organic compounds from water in the oilsands tailings. In this instance, the nanogas solution includes nitrogennanobubbles, oxygen nanobubbles, carbon dioxide nanobubbles or a mixturethereof. In one case, the nanogas solution is a nitrogen-nanogassolution. In another case, the viscosity of oil in the tailings isreduced as an effect of the addition of the nanogas solution. In yetanother case includes further admixing an oxygen-nanogas solution withthe oil sands tailings; and oxidizing a sulfide. The process canincludes admixing the nanogas solution with the tailings and then addingthe admixture to a tailings pond; can include subservice injection andadmixing of the nanogas solution and the tailings, for example thesubsurface injection of the nanogas solution into tailings held in atailings pond.

Still another embodiment is a method for oxidizing sulfides. In oneinstance this method can include admixing an oxygen-nanogas solution oran ON-nanogas solution with an aqueous solution that includes hydrogensulfide and oxidizing the hydrogen sulfide. In another instance thismethod can include admixing an oxygen-nanogas solution or an ON-nanogassolution with a slurry of iron sulfide and water and oxidizing the ironsulfide to iron oxide.

1. A process comprising: shearing a first nanogas solution into anoil-in-water micro emulsion; breaking the oil-in-water micro emulsionand forming a water-in-oil macro emulsion, a water phase, and a solidsphase, where the water-in-oil macro emulsion is carried on the waterphase; and collecting oil from the water-in-oil macro emulsion; whereinthe nanogas solution consists essentially of a homogeneous mixture ofnanobubbles and water.
 2. The process of claim 1 further comprisingseparating the water phase from the water-in-oil macro emulsion and thesolids; wherein the separated water phase includes nanobubbles.
 3. Theprocess of claim 2 further comprising recycling a portion of the waterphase; and using the recycled portion of the water phase to provide thefirst nanogas solution.
 4. The process of claim 1, wherein theoil-in-water micro emulsion includes emulsifiers selected from solids,asphaltenes, paraffins, resins, and mixtures thereof.
 5. The process ofclaim 4, wherein the first nanogas solution is an oxygen-nanogassolution; the process further comprising absorbing oxygen nanobubblesinto the emulsifiers, reducing the zeta potential of an oil droplet, andforming an admixture that includes a coagulum; wherein the coagulumcomprises an oil-in-water macro emulsion.
 6. The process of claim 5,further comprising admixing a second nanogas solution with the admixturethat includes the coagulum, where the second nanogas solution is anitrogen-nanogas solution; dissociating the emulsifiers from a surfaceof oil droplets in the oil-in-water macro emulsion; breaking theoil-in-water emulsion; and forming the water-in-oil macro emulsion. 7.The process of claim 4, wherein the first nanogas solution is anitrogen-nanogas solution; the process further comprising dissociatingthe emulsifiers from a surface of oil droplets in the oil-in-water macroemulsion; breaking the oil-in-water emulsion; and forming thewater-in-oil macro emulsion.
 8. The process of claim 1, wherein thefirst nanogas solution includes carbon dioxide and nitrogen; the processfurther comprising absorbing the carbon dioxide into an oil droplet; andreducing the density of the oil droplet; wherein the water-in-oil macroemulsion includes carbon dioxide in the oil.
 9. The process of claim 1,wherein the oil-in-water micro emulsion includes a concentration ofsulfides greater than 50 ppm, the sulfides selected from iron sulfide,hydrogen sulfide, and a mixture thereof; wherein either (a) the firstnanogas solution includes a sufficient quantity of oxygen nanobubbles toreact completely with the concentration of sulfides in the oil-in-wateremulsion, thereby reducing the sulfide concentration to less than 10ppm, or (b) the process further includes admixing a second nanogassolution with the water phase, wherein the sulfides of the oil-in-watermicro emulsion are carried into the water phase, and where the secondnanogas solution includes a sufficient quantity of oxygen nanobubbles toreact completely with the concentration of sulfides in the water phase,thereby reducing a sulfide concentration to less than 10 ppm.
 10. Theprocess of claim 1 further comprising providing a flow of theoil-in-water micro emulsion; wherein shearing the first nanogas solutioninto the oil-in-water micro emulsion includes injecting a stream of thefirst nanogas solution into the micro emulsion flow at a direction thatis 90° to 180° from the flow, preferably 115° to 180°, more preferably135° to 180°.
 11. The process of claim 1, wherein shearing the firstnanogas solution into the oil-in-water micro emulsion includes admixingthe first nanogas solution and the micro emulsion in a mixer; theprocess further including ejecting this admixture into a separationcontainer.
 12. The process of claim 1, wherein the first nanogassolution does not form macrobubbles.
 13. The process of claim 1, whereinthe water-in-oil macro emulsion does not include macrobubbles.
 14. Theprocess of claim 1, wherein the water-in-oil macro emulsion includesgreater than about 50 wt. % oil and less than about 50 wt. % water;wherein the water-in-oil macro emulsion further includes nanobubbles.15. A process comprising: providing a floatation tank having an inletend and an outlet end; the floatation tank including an oil-in-wateremulsion inlet and a first nanogas inlet, both, proximal to the inletend, and having an underflow baffle proximal to the outlet end;providing an oil-in-water emulsion to the floatation tank via theoil-in-water emulsion inlet; providing a nanogas solution to thefloatation tank via the first nanogas inlet by injecting a stream of ananogas solution into a flow path of the oil-in-water emulsion at adirection that is 90° to 180° from the flow path, preferably 115° to180°, more preferably 135° to 180°, thereby admixing the nanogassolution with the oil-in-water emulsion without the formation ofmacrobubbles; breaking the oil-in-water emulsion and forming an oilphase floating on a water phase; separating the water phase from the oilphase by carrying the water phase under the underflow baffle.
 16. Theprocess of claim 15, wherein the floatation tank includes a secondnanogas inlet downstream from the first nanogas inlet and upstream fromthe underflow baffle; the process further including providing a secondnanogas solution to the floatation tank via the second nanogas inletthereby admixing the second nanogas solution with the water phasecarrying the oil phase.
 17. A method comprising: admixing anitrogen-nanogas solution with oil sands tailings; separating materialsincluding silts, residual bitumen, and organic compounds from water inthe oil sands tailings; wherein the nitrogen-nanogas solution includesnitrogen nanobubbles; wherein the viscosity of oil in the tailings isreduced as an effect of the addition of the nitrogen-nanogas solution.18. (canceled)
 19. (canceled)
 20. The method of claim 17 furthercomprising admixing an oxygen-nanogas solution with the oil sandstailings; and oxidizing a sulfide.
 21. The method of claim 17 furthercomprising admixing the nitrogen-nanogas solution with the tailings andthen adding the admixture to a tailings pond.
 22. The method of claim17, wherein admixing the nitrogen-nanogas solution and the tailingsincludes subsurface injection of the nitrogen-nanogas solution intotailings held in a tailings pond.
 23. (canceled)
 24. (canceled)